Flow of formation fluids into the wellbore during drilling operations is called an influx or “kick.” By contrast, a fluid loss occurs when drilling fluid in the wellbore is lost to the formation, which can have a number of detrimental effects. If a kick cannot be detected and controlled fast enough, it can escalate into uncontrolled flow of formation fluids to the surface, which is called a “blow-out.” Consequences from this may vary from operational delays (non-productive time) to more severe damage. Hydrostatic pressure is the first conventional barrier for controlling the well, and rig blow out preventers (BOP) are the second barrier.
For these reasons, early and accurate kick detection is critical during drilling operations to maintain proper hydrostatic pressure in the well. Warning signs that are conventionally looked for when detecting a kick are not always clear (ROP and hook load change), or the signs may arrive too late (change in cutting size, Chloride level, etc.). Sometimes, the frequency at which data is collected (standpipe pressure readings) may be too slow to properly detect a kick. Moreover, measurements of return flow (i.e., flow-out) of the well may be subject to uncertainties due to heave effects, mud transfers, and imprecision in tank level measurements.
So far, improved kick detection has been achieved by continuously monitoring the return flow (i.e., flow-out) in a closed-loop circulation system and comparing the flow-out to the flow-in. Several controlled pressure drilling techniques have been used to drill wellbores with such closed-loop drilling systems. In general, the controlled pressure drilling techniques include managed pressure drilling (MPD), underbalanced drilling (UBD), and air drilling (AD) operations.
In the Managed Pressure Drilling (MPD) technique, for example, the drilling system uses a closed and pressurizable mud-return system, a rotating control device (RCD), and a choke manifold to control the wellbore pressure during drilling. The various MPD techniques used in the industry allow operators to drill successfully in conditions where conventional technology simply will not work by allowing operators to manage the pressure in a controlled fashion during drilling.
As the bit drills through a formation, for example, pores become exposed and opened. As a result, formation fluids (i.e., gas) from an influx or kick can mix with the drilling mud. The drilling system then pumps this gas, drilling mud, and the formation cuttings back to the surface. As the gas rises up the borehole, the gas may expand, and hydrostatic pressure may decrease, meaning more gas from the formation may be able to enter the wellbore. If the hydrostatic pressure is less than the formation pressure, then even more gas can enter the wellbore.
As a primary function, managed pressure drilling attempts to control such kicks or influxes of fluid. This can be achieved using an automated choke response in the closed and pressurized circulating system made possible by the rotating control device. A control system controls the chokes with an automated response by monitoring the flow-in and the flow-out of the well, and software algorithms in the control system seek to maintain a mass flow balance. If a deviation from mass balance is identified, the control system initiates an automated choke response that changes the well's annular pressure profile and thereby changes the wellbore's equivalent mud weight. This automated capability of the control system allows the system to perform dynamic well control or constant bottom hole pressure (CBHP) techniques.
As an example, FIG. 1 shows an existing detection technique 100 in flow chart form for detecting a kick or influx during drilling with a closed-looped system. In the current technique 100, the system monitors parameters while drilling (Block 102). These monitored parameters typically include flow-in, flow-out, mud-weight levels, pit levels, pump pressure, surface leaks, trip-tank levels, etc. Using the monitored parameters, the system analyzes trends in the flow-out, standpipe pressure, and density (Decision 104) to determine whether an influx is detected (Block 110) or not.
In particular, the system monitors whether the flow-out has been increasing for a time interval (e.g., 15-seconds), whether the standpipe pressure has increased less than a first threshold (e.g., 5-psi), and whether the density has decreased less than a second threshold (e.g., 0.1-ppg). If not, the system determines whether flow-out is decreasing as a trend (Decision 106) and, if so, indicates that a loss is detected (Block 108). Otherwise, the system merely returns to monitoring (Block 102).
Should the system determine that the flow-out has been increasing for the time interval, the standpipe pressure has increased less than the first threshold, and the density has decreased less than the second threshold (yes at decision 104), then the system determines if an influx has been detected (Block 110). If an influx has been detected and if auto control features are enabled (Decision 112), then the system handles the influx by controlling and circulating out the detected kick (Block 114).
In the end, the detection technique 100 determines the state of a kick event or not based on the previous indications. In this sense, the technique 100 checks for the flow-out to increase as a trend line while the flow-in remains the same by averaging a last “n” number of readings to detect an influx. The “trend time” defined by the user directly changes the effectiveness of the detection technique. If the trend time is relatively small, the technique may be over-sensitive and may detect false kicks. If the trend time is relatively large, the system may not detect kicks because the technique 100 cannot sense the sudden increases in flow-out and SPP followed by a decrease indicative of a kick. Considering that various kicks come with different signatures, the dependability of the technique 100 for kick detection depends on how many false kicks will the operators tolerate during operation so that the system can still be able to detect true kicks properly.
As can be seen above, current kick detection methods compare parameters of the flow-in and flow-out of the well in conjunction with the standpipe pressure (SPP)'s behavior. As soon as the kick shows the expected characteristics, the current methods can successfully detect the kicks. However, in many cases, current methods do not detect various kicks because the characteristics of the kick may be different than expected, or the methods make false detections. As can be appreciated, any false kick detections are disconcerting. Further, any remedial steps required after a detect kick (even falsely) to close the well, make reports, stand down operations, and the like can be significant hurdles to the drilling progress. Therefore, operators want more reliability in kick detection and control.
According to additional problems, conventional kick detection techniques determine a kick by a volumetric change between flow-in and flow-out. However, the current techniques assume that the variables of interest, such as flow-in and flow-out, are steady-state, and unfortunately, volumetric changes are not always a good indicator of a fluid influx. For example, an increase in fluid in the drilling system may not always be due to an influx, even though it could be background gas. Moreover, current techniques assume that changes in pressure are instantaneous. In reality, pressure changes must propagate over time through the drilling system.
The subject matter of the present disclosure is directed to overcoming, or at least reducing the effects of, one or more of the problems set forth above.